Thermal energy delivery and oil production arrangements and methods thereof

ABSTRACT

Thermal energy delivery and oil production arrangements and methods thereof are disclosed which heat a subterranean formation ( 132 ), and which comprises positioning concentric tubing strings ( 220 ) in a wellbore ( 130 ); heating a heat transfer fluid ( 250 ) using a surface thermal fluid heater ( 186 ); flowing a liquid or feedwater ( 142 ) downward through an extremely hot innermost tubing string ( 248 ) that is inside and concentric to an outermost tubing string ( 252 ) and a casing/annulus ( 260 ), which extends below a thermal packer ( 156 ) positioned in the wellbore, and continually circulating the heat transfer fluid through the outermost tubing string and the casing/annulus above the thermal packer such that the liquid or feedwater flowing through the innermost tubing string is heated thereby and injected into the wellbore below the thermal packer and out of perforations to heat the subterranean formation to temperatures that allow for hydrocarbon production from the subterranean formation. Emissions may be injected into the subterranean formation with the liquid or feedwater.

TECHNICAL FIELD

The present disclosure relates generally to methods and systems forproduction of hydrocarbons from various subterranean formations throughthe use of downhole thermal energy delivery and oil productionarrangements and methods thereof.

BACKGROUND

Steam injection is used to lower the viscosity of heavy oil and oilsands trapped in the underground rock formations, such that it flowsthrough the reservoir and can be recovered by conventional methods.Additionally, steam injection is used in light oil formations toincrease recovery of residual oil after depletion of reservoir pressure.Pressurized steam can add new pressure to the light oil subterraneandeposit, in that as the injection steam condenses to water, the waterwill act as a drive mechanism to push the oil through the reservoir tothe production wells. Studies have shown that steam distillationimproves light oil recovery from thin reservoirs. Steam distillationmeans that steam injection will cause some volatile components of thecrude to enter a vapor phase. Moreover, steam injection can be used inthe production of methane hydrate and the remediation of groundwatercontamination.

SUMMARY

Various embodiments of the present invention provide for improveddelivery of downhole thermal energy, or heat and high-pressure,high-quality downhole steam, to increase the efficiency of recovery ofhydrocarbons from a subterranean formation.

In some embodiments, an in situ heat treatment system for producinghydrocarbons from a subterranean formation that includes a wellbore inthe subterranean formation is disclosed. Concentric tubing strings arepositioned in the wellbore along with a thermal packer that is alsopositioned in the wellbore. A non-toxic hot heat transfer fluid closedloop circulation system is coupled to the outermost tubing string, andthe casing/annulus for a relatively cooled, hot heat transfer fluid toreturn to the surface to be reheated in the thermal fluid heater andrecirculate down hole. A liquid supply, hot feedwater, is configured toprovide through a hot permanent innermost tubing string of theconcentric tubing strings that is inside and concentric to the outermosttubing string. A thermal fluid heater is configured on the surface toheat the non-toxic hot heat transfer fluid continually circulatedthrough the outermost tubing string above the thermal packer positionedin the wellbore to immediately convert the liquid, which descends in theinnermost tubing string, into high-pressure, high-quality downholesteam, wherein the permanent innermost tubing string extends below thesurface such that the liquid immediately converts to high-pressure,high-quality downhole steam inside the innermost hot tubing string thatminimizes or eliminates heat loss and is injected into the steaminjection wellbore below the thermal packer to heat the subterraneanformation to temperatures that allow for viscous hydrocarbon productionfrom the subterranean formation.

In some embodiments, a method of heating a subterranean formation isdisclosed. The method includes positioning concentric tubing strings ina wellbore; heating a non-toxic hot heat transfer fluid using a surfacethermal fluid heater; and flowing a liquid downward through a hotinnermost tubing string of the concentric tubing strings that is insideand concentric to the outermost tubing string, which does not convert toa vapor phase for a time period and extends below a thermal packerpositioned in the wellbore to achieve a hot fluid injection in thesubterranean formation. The method also may include continuallycirculating the non-toxic hot heat transfer fluid through the outermosttubing string above the thermal packer such that the liquid flowingthrough the hot innermost tubing string after the time period isconverted into high-pressure, high-quality downhole steam, which isinjected into the wellbore below the thermal packer and out of theperforations to heat the subterranean formation to temperatures thatallow for hydrocarbon production from the subterranean formation.

In some embodiments, a method of heating a subterranean formation isdisclosed. The method includes positioning concentric tubing strings ina wellbore; heating a non-toxic hot heat transfer fluid using a surfacethermal fluid heater; and flowing a liquid downward through a hotinnermost tubing string of the concentric tubing strings that is insideand concentric to the outermost tubing string, which does not convert toa vapor phase for a time period and extends below a thermal packerpositioned in the wellbore to achieve a hot fluid injection in thesubterranean formation. The method also may include continuallycirculating the hot heat transfer fluid through the outermost tubingstring above the thermal packer such that the liquid flowing through thevery hot innermost tubing string after the time period is converted intohigh-pressure, high-quality downhole steam, which is injected into thewellbore below the thermal packer and out of the perforations to heatthe subterranean formation to temperatures that allow for recovery ofvolatile and semi-volatile organic contaminants from the subterraneanformation or degradation by natural attenuation processes.

These and other features and advantages of this invention will becomemore apparent to those skilled in the art from the detailed descriptionof various embodiment discussed below.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawings that accompany the detailed description are describedbelow, wherein like numerals refer to like parts, elements, components,etc., and in which:

FIG. 1 is a schematic illustration of a vertical wellbore for a cyclicsteam stimulation or huff and puff for high-quality downhole steamgeneration and oil production arrangement in accordance with anembodiment;

FIG. 2 is a schematic illustration of a vertical wellbore with asimultaneous downhole steam injection and oil production arrangement inaccordance with an embodiment;

FIG. 2A is a cross-section view of concentric tubing strings provided inthe arrangement of FIG. 2 and taken along section line 2A-2A;

FIG. 3 is a schematic illustration of a vertical wellbore with ahigh-quality downhole steam generation and oil production arrangementincluding CO2 and NOx emissions injection in a subterranean formationfor sequestration of the emissions in accordance with anotherembodiment;

FIG. 3A is a cross-section view of concentric tubing strings provided inthe arrangement of FIG. 2 and taken along section line 3A-3A;

FIG. 4 is a schematic illustration of a vertical wellbore with ahigh-quality downhole steam generation and oil production arrangementfor non-thermally completed wells in accordance with still anotherembodiment;

FIG. 4A is a cross-section view of concentric tubing strings provided inthe arrangement of FIG. 4 and taken along section line 4A-4A;

FIG. 5 is a schematic illustration of a vertical wellbore with ahigh-quality downhole steam generation and oil production arrangementknown as steam drive or steam flooding in accordance with yet anotherembodiment;

FIG. 5A is a cross-section view of concentric tubing strings provided inthe arrangement of FIG. 5 and taken along section line 5A-5A;

FIG. 6 is a schematic illustration of the embodiment of FIG. 5configured for steam assisted gravity drainage (SAGD);

FIG. 6A is a cross-section view of concentric tubing strings provided inthe arrangement of FIG. 6 and taken along section line 6A-6A;

FIG. 7 is a schematic illustration of the embodiment of FIG. 5configured for steam assisted gravity drainage (SAGD) with a perforatedpipe or slotted liner;

FIG. 7A is a cross-section view of concentric tubing strings provided inthe arrangement of FIG. 7 and taken along section line 7A-7A;

FIG. 8 is a schematic illustration of the embodiment of FIG. 5configured for steam assisted gravity drainage (SAGD) with steamchambers;

FIG. 8A is a cross-section view of concentric tubing strings provided inthe arrangement of FIG. 8 and taken along section line 8A-8A;

FIG. 9 is a schematic illustration of the embodiment of FIG. 5configured for steam assisted gravity drainage (SAGD) with severalmultilateral wellbores for high-quality downhole steam generation andoil production arrangement;

FIG. 9A is a cross-section view of concentric tubing strings provided inthe arrangement of FIG. 9 and taken along section line 9A-9A;

FIG. 10 is a schematic illustration of a vertical wellbore with ahigh-quality downhole steam generation and oil production arrangementknown as cyclic steam stimulation or huff-and-puff in accordance with anembodiment;

FIG. 10A is a cross-section view of concentric tubing strings providedin the arrangement of FIG. 10 and taken along section line 10A-10A;

FIG. 11 is a schematic illustration of a vertical wellbore with asimultaneous downhole hot fluid injection and oil productionarrangement;

FIG. 11A is a cross-section view of concentric tubing strings providedin the arrangement of FIG. 11 and taken along section line 11A-11A;

FIG. 12 is a schematic illustration of a hot fluid injection arrangementconfigured for a surface heat exchanger; and

FIG. 12A is a cross-section view of concentric tubing strings providedin the arrangement of FIG. 12 and taken along section line 12A-12A.

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and may herein be described in detail. Thedrawings are not to scale. It should be understood, however, that thedrawings and detailed description thereto are not intended to limit theinvention to the particular form disclosed, but on the contrary, theintention is to cover all modifications, equivalents and alternativesfalling within the spirit and scope of the present invention as definedby the appended claims.

DETAILED DESCRIPTION

Embodiments of the present invention are directed to various methods andsystems for recovering petroleum resources using vertical, horizontaland lateral wellbores in geological subterranean formation strata from avertical position. The geological structures intended to be penetratedin this fashion may be coal seams, uranium, methane hydrate, oil sands,heavy and light hydrocarbons from a subterranean formation bearingstrata for increasing the flow rate from a pre-existing wellbore. Otherpossible uses for the disclosed embodiments can be used for highpressure high-quality downhole steam injection for steam fracking of lowpermeability subterranean formations such as low gravity heavy oil,diatomite, tight oil, shale oil, shale gas, leaching of uranium ore andsulfur from subterranean formations or for introducing horizontal andvertical channels for steam injection, heated solvents, and chemicals,for example. Those skilled in the art will understand that the variousembodiments disclosed herein may have other uses which are contemplatedwithin the scope of the present invention.

Referring to FIG. 1, a cross-sectional view of an embodiment of a cyclicsteam stimulation or huff and puff of high-quality downhole steamgeneration arrangement 100 in accordance with an embodiment of thepresent invention is illustrated. In accordance with the arrangement 100of FIG. 1, vertical wellbore 130 heat losses resulting in lower qualitysteam is reduced through the use of a high-quality downhole steamgeneration section 110 of a vertical wellbore 130.

Referring to FIGS. 2 and 2A, the embodiment of a simultaneous steaminjection and oil production arrangement 101 is depicted in which thehigh-quality downhole steam generation section 110 comprises anarrangement of concentric tubing strings 220 positioned within thevertical wellbore 130 that is formed in a subterranean formation 132 torecover deposits 134 therefrom. In various embodiments, the depth of thehigh-quality downhole steam generation section 110 will vary accordingto the depth of the subterranean formation 132. For example, in variousembodiments, the depth of the vertical wellbore 130 from a surface 136above the subterranean formation 132 may be between several hundred feetand 10,000 thousand feet or more. A discussion on how the high-qualitydownhole steam generation and oil production arrangement 100 depicted byFIG. 1 and the simultaneous steam injection and oil productionarrangement 101 depicted by FIG. 2 are configured and operated torecover the deposits 134 from the subterranean formation 132 nowfollows.

The concentricity of the various tubing strings in the vertical wellbore130 in the cross-sectional view of FIG. 2A and taken along section line2A-2A in FIG. 2. In the illustrated embodiments, the surface pump 140advances a liquid 142 comprising hot feedwater from a surface storagetank 144 through a conduit 146 and down into the vertical wellbore 130to the area of the subterranean formation 132 via an innermost tubingstring 248 of the concentric tubing strings 220. Likewise, with the aidof heat from a recirculating hot heat transfer fluid 250 flowing downinto the vertical wellbore 130 via an outermost tubing string of theconcentric tubing strings 220, the liquid is converted into a vapor byheat transfer exchange of heat from the recirculating hot heat transferfluid 250 in the high-quality downhole steam generation section 110 ofthe vertical wellbore 130. Therefore, no downhole combustion takes placeat the site of steam generation in the downhole tubing.

Within the scope of the subject invention, and as appropriate todifferent subterranean and deposit formations, the liquid 142 maycomprise other liquids in addition to or other than water. By way ofexample, the substance with which deposits are releasable in a vaporphase may be employed in the form of oil convertible at the subterraneanformation to oil vapor. The liquid 142 may, for example, comprise dieseloil or gas oil. Additionally, the liquid 142 injected into the innermosttubing string 248 is provided between the surface pump 140 and innermosttubing string 248. For example, in an embodiment the liquid 142 is a hotfeedwater that is injected at a super critical hot water temperature andpressure to maximize the thermal energy prior to conversion tohigh-quality downhole steam being delivered to the hydrocarbons in thesubterranean formation 132.

As depicted, the outermost tubing string 252 surrounds the innermosttubing string 248 from a well head 154, which sealing the verticalwellbore 130 at the surface 136, down to a position adjacent or above ofa thermal packer 156. This shorting of the outermost tubing string 252relative to the innermost tubing string 248 leaves a downhole section158 of the innermost tubing string 248 that is not surrounded by theoutermost tubing string 252 or casing/annulus 260. This downhole section158 permits a casing/annulus 260 of the concentric tubing strings 220 toact as a recirculation conduit for the return of the cooled hot heattransfer fluid 250 to the surface 136 for reheating after exchangingheat, from the well head 154 to the top of the thermal packer 156, tothe liquid 142 flowing downwards in the vertical wellbore 130 via thehot innermost tubing string 248. In an embodiment, the length of thedownhole section 158 from the distal end 262 of outermost tubing string252 to the top (surface) of the thermal packer 156 may range fromseveral hundred feet to 10,000 feet or deeper. In another embodiment,the outermost tubing string 252 may extend to the top of the thermalpacker 156 and perforations, slot, etc. (not shown) opening to thecasing/annulus 260 may be provided in the outermost tubing string 252above the thermal packer 156. In either of the above disclosedembodiments, it is to be appreciated that the outermost tubing string252 is in fluid communication with the casing/annulus 260 such that thehot heat transfer fluid 250 can be continually circulated from thesurface 136, down the outermost tubing string 252, up the casing/annulus260, and back to the surface 136, or vice-versa. In this manner, the hotheat transfer fluid 250 is constantly recycled and recirculated and keptfrom escaping into the subterranean formation 132, and thereby iseconomically preserved.

As shown by FIG. 1 and FIG. 2, the thermal packer 156 seals a lowersection 164 of the vertical wellbore 130 or the casing/annulus 260 fromthe high-quality downhole steam generation section 110 and thecasing/annulus 260 above the thermal packer 156. The innermost tubingstring 248 extends through the thermal packer 156 and opens into thelower section 164. In this manner, the downwardly flowing liquid 142which has been converted into a vapor from the heat applied against thehot innermost tubing string 248 by the circulating hot heat transferfluid 250 in the high-quality downhole steam generation section 110, isinjected or pressure driven into the subterranean formation 132.

It is to be appreciated that at a certain depth of the vertical wellbore130 in the high-quality downhole steam generation section 110, the hotheat transfer fluid 250 flowing in the outermost tubing string 252flashes the liquid 142 flowing in the extremely hot innermost tubingstring 248 into high-quality downhole steam 166 which is directedthrough perforations 168 provided in the casing/annulus 260, and intothe subterranean formation 132. As the heat energy of the hot heattransfer fluid 250 is exchanged to the liquid 142 throughout thehigh-quality downhole steam generation section 110, continued heating ofthe steam 166 downhole likewise can occur in the high-quality downholesteam generation section 110, which based on controlled operatingtemperatures, pressures and flow rates of the liquid 142 and hot heattransfer fluid 250 can result in a range of steam quality as well assuperheated steam being provided to the subterranean formation 132 asdesired. Additionally, controlling the sequence of providing the flow ofliquid 142 and the hot heat transfer fluid 250 into the verticalwellbore 130, the subterranean formation 132 may be subjected to hotwater injection or hot fluid injection for thermal stimulation andenhanced recovery of the deposit.

As used in this application, the phrase “high-pressure steam” meanssteam having a pressure ranging from 1,000 to 2,500 psia. As used inthis application, the phrase “hot water or hot oil (fluid) injection”means a fluid having a temperature ranging from 100 to 500 degrees F. Asused in this application, the phrase “high-quality steam” means a steamquality of 0.80 or more, with steam quality being the proportion ofsaturated steam (vapor) in a saturated condensate (liquid)/steam (vapor)mixture. For example, a steam quality of 0 indicates 100% liquid(condensate) while a steam quality of 1 indicates 100% steam. One pound(1 lb) of steam with 95% steam and 5% percent of liquid entrainment hasa steam quality (also called, steam dryness), of 0.95. The steam qualityor dryness fraction is used to quantify the amount of water withinsteam. Steam dryness has a direct effect on the total amount oftransferable energy contained within the steam (usually just latentheat), which affects heating efficiency and quality. Saturated steam(meaning steam that is saturated with heat energy) is completely gaseousand contains no liquid. Conventional surface steam boilers do notgenerate 100% saturated steam or dry steam. When a steam boiler heats upwater, bubbles breaking through the water surface will pull tiny waterdroplets in with the steam. Unless a super heater is used to super heatthe steam, this will cause the steam supply to become partially wet (wetsteam) from the added liquid. Superheated steam is a type of steam thatis created by adding heat above the saturated steam threshold. The addedheat raises the steam's temperature higher than its saturation point,allowing the amount of superheat to be easily determined by simplymeasuring its temperature.

A major drawback of prior art, conventional surface steam boilers,requires very pure water to have any chance of operating and to reducethe scale on the tubing that affects the heat transfer. Since the costof pure water in remote areas is very costly those processes areobviously uneconomical in most cases. The embodiments of the presentinvention have no such requirement and can operate with contaminatedwater or produced brackish water of high mineral content. Additionally,even a downhole-recovered condensate of the vapor or super heated steammay be employed.

It is to be appreciated that in the arrangements 100 and 101, the heattransfer from the thermal fluid to the liquid for generatinghigh-quality downhole steam occurs downhole in the vertical wellbore 130and not on the surface 136. Therefore, scale may occur downhole on thetubing. Mitigation of the reduction and/or removal of scale may beaccomplished with the aid of a scale inhibitive solution, which may bepumped downhole from a tank by pumps into the innermost tubing string248. In the alternative, a common oil field practice is the use of acidto stimulate a subterranean formation. As an alternative to this concepta truck with a tank filled with acid can be employed to do an acid washof the scale build-up within the innermost tubing string 248 allowingthe scale to be washed off the tubing and drop down to the rat hole atthe bottom of the vertical wellbore 130. In addition to or in thealternative, high-pressure jetting scale removal may be employed. Thiswill enable the high-quality downhole steam generation tubing, i.e.innermost tubing string 248, to be almost free of scale build-up thatwill improve the surface area and heat transfer area for conversion ofliquid to high-quality downhole steam. Suitable substances for theinhibitive solution include acetic acid, hydrochloric acid, and sulfuricacid in sufficiently low concentration to avoid damage to the system andavoid an environmental issue in the reservoir.

Combining the high-quality downhole steam 166 in such a manner withother methods will also enhance the recovery of the deposits 134therefrom. For example, some of the other methods may include having theliquid 142 also comprise, in addition to water, heated solvents and/orsurfactants as well as supplementing such with heated gas(es).Surfactants are compounds that lower the surface tension of a liquid,the interfacial tension between two liquids, or that between a liquidand a solid. Surfactants may act as wetting agents, emulsifiers, foamingagents, and dispersants. Surfactants are usually organic compounds thatare amphiphilic, meaning they contain both hydrophobic groups andhydrophilic groups. Therefore, a surfactant molecule contains both awater insoluble (and oil soluble) component and a water solublecomponent. Surfactant molecules will diffuse in water and adsorb atinterfaces between air and water or at the interface between oil andwater, in the case where water is mixed with oil.

Surfactants and solvents combined with downhole steam injection have thepotential to significantly increase oil recovery over that ofconventional water flooding. The availability of a large number ofsurfactant structures makes it possible to conduct a systematic study ofthe relation between surfactant structure and its efficacy for oilrecovery. Also, the addition of an alkali such as sodium carbonate makespossible in-situ generation of surfactant and significant reduction ofsurfactant adsorption. In addition to reduction of interfacial tensionto ultra-low values, surfactants and alkali can be designed to alterwettability followed by steam injection to enhance oil recovery.

An alkaline surfactant process is designed to enhance spontaneousimbibition in fractured, oil-wet, carbonate formations. Mobility controlis essential for steam-surfactant EOR to improve the sweep efficiency ofsurfactant and steam injected into fractured reservoirs. The placementof a catalyst downhole can improve cyclic steam, heavy-oil recovery byupgrading the produced oil downhole by increasing the saturate andaromatic components and reducing the resin and asphaltene components.The term “aquathermolysis” describes the chemical interaction of hightemperature, high-pressure water with the reactive components of heavyoil and bitumen.

In aquathermolysis, the metal species added to steam interact withorganic sulfur compounds. In a huff-and-puff operation theaquathermolysis catalyst will reduce the oil viscosity downhole by morethan 60% and substantially increase the oil production for the steamcycle. The metal species in the catalyst for this improvement containedVO²⁺, Ni²⁺, Fe³⁺ and other additives. The vanadyl sulfate and nickelsulfate are the catalysts for the aquathermolysis of heavy oils, andferric sulfate is the catalyst for the water-gas shift reaction. At theend of aquathermolysis, the water-gas shift reaction is a major reactionfor forming CO₂ and H₂. It is determined that the above catalyst cansignificantly alter the composition of heavy oil and, therefore, theheavy oil is upgraded in the reservoir to a higher API gravity oil orlighter oil by removing the asphaltenes. Activating the silica column,obtaining the saturate and aromatic fractions by elution with hexane.What occurs is an oil composition change. After the catalytic treatment,the oil has more saturate and aromatic components, which are lighter,and less resin and asphaltene components, which are heavier. The resultsof the above catalyst indicate that during aromatization some cyclichydrocarbons were converted into aromatics. Some normal and iso-alkylside chains, which are at the edge of the condensed aromatic core inresin and asphaltene molecules, broke off from the condensed aromaticand then converted into alkyl hydrocarbons. The alkyl chain, which linkstwo condensed aromatics in large molecular structures of resin andasphaltene, may break off, and thus the amount of resin and asphaltenedecreased and the amount of aromatics increased. In the process, theheavy oil undergoes aquathermolysis during steam injection, and thecatalyst injected with steam can accelerate the reaction, resulting in areduced viscosity and a changed composition of the produced oil thatresults in higher API gravity lighter oil. With a catalyst added to thesteam, the metallic ions can interact with water. The proton from thecomplex molecule can attack the sulfur atom, and the hydroxide ion canattack the carbon atom. This result in the electronic cloud excursionand leads to a further decrease in bond energy. Because of this, the C—Sbond will break in the process of aquathermolysis and result in a lowamount of sulfur and heavy components such as resin and asphaltene.

In the aquathermolysis process, H₂S will be produced because of thedesulfurization of heavy oil. Recently it has been suggested thatgaseous H₂S may promote the water-gas shift reaction through theintermediate formation of carbonyl sulfide (COS). At the same time, H₂Swill react with the metal ions and produce metal sulfides. It is wellknown that metal sulfides are useful catalysts for hydrode-sulfuriztionof heavy oil. The analysis found that all transition metal species havethe ability to accelerate the decomposition of the sulfur compoundsregardless of whether the sulfur was in an aromatics or an aliphaticenvironment. Among all the transition metal species, VO²⁺ and Ni²⁺ arethe most effective for aquathermolysis of heavy oil.

Oil reservoirs are large porous medium that contain sands, clayminerals, and non-clay minerals. The clay mineral surface has a negativecharge. When the catalyst solution is injected into the oil reservoir,the metal ions, such as VO²⁺ and Ni²⁺, can be adsorbed on the surface ofclay minerals via the electrostatic force. Under this circumstance, theminerals support the catalyst in a similar manner as in a typicalrefinery process.

At the same time, the steam injected into the oil reservoir reacts withmost of the rock minerals and clay minerals. Clay minerals aresilica-aluminate compounds that under high temperature can react withsteam and swell up in the formation preventing a successful steamdistribution.

As mentioned above, the high-pressure, high-quality downhole steam 166produced from the liquid 142 is driven or injected into the subterraneanformation 132 releasing e.g., hydrocarbons from the deposits 134therein. The high-quality downhole steam 166 adds thermal energy to thedeposits 134 and, in the example of hydrocarbons, serves to reduce theviscosity of the hydrocarbons from the subterranean formation deposit.Reducing the viscosity of the hydrocarbons causes the hydrocarbons fromthe subterranean formation 132 to flow into the vertical wellbore 130,into another adjacent vertical wellbore (if provided) or downwardsdeeper into the subterranean formation 132 to another adjacenthorizontal wellbore(s) or lateral wellbore(s) (if provided), due togravity drainage.

In the illustrated embodiments of FIG. 1 and FIG. 2, the hydrocarbonsfrom the subterranean formation 132 which flow into the verticalwellbore 130 are captured and pumped to the surface 136 through a suckerrod and pump 270 and/or an electrical submersible pump (ESP) 272 throughan oil production outlet conduit 178 to one or more tanks 174 on thesurface 136. In this regard, the electrical submersible pump (ESP) 272and/or the sucker rod and pump 270 are provided at a point sufficientlydeep within the vertical wellbore 130 to pump the flowing hydrocarbonsto the surface. The electrical submersible pump (ESP) 272 and allelectrical cabling necessary for operation and control of the electricalsubmersible pump (ESP) 272 are provided within an innermost tubingstring 276 which can also include the sucker rod and pump 270. In theillustrated embodiment of FIG. 2, the innermost tubing string 276 isconcentric with the other tubing strings 248, 252, 260 of the concentrictubing strings 220 in the arrangement 101. In other embodimentsdiscussed hereafter in later sections, the sucker rod and pump 270and/or electrical submersible pump (ESP) 272 or progressive cavity pump(PCP) may be positioned differently.

It is to be appreciated that a cyclic action referred to as cyclic steamstimulation or “huff and puff” can be provided using the arrangement 100of FIG. 1 and/or FIG. 10. Referring to FIGS. 2 and 11 (discussed furtherhereafter in a later section), unlike conventional cyclic steamstimulation arrangements, due to the sucker rod and pump 270 and/or theelectrical submersible pump (ESP) 272 being provided within theinnermost tubing string 276 in the arrangements 101 and 1100, separatesteam lines/tubing arrangements do not have to be removed from thevertical wellbore 130 before or after a steam cycle in order to installthe sucker rod and pump 270 and/or the electrical submersible pump (ESP)272 along with a separate oil production outlet conduit 178 in order torecover the hydrocarbons from the vertical wellbore 130. In other words,the generation and providing of the high-quality downhole steam 166 inthe vertical wellbore 130 as well as the capturing and pumping of thehydrocarbons to the surface 136 from the vertical wellbore 130 may takeplace simultaneously. Additionally, some other noted advantages of thesimultaneous high-quality downhole steam injection and oil productionarrangement 101 (FIG. 2) and a hot fluid injection and oil productionarrangement 1100 (FIG. 11) are the cost savings of a production rig,labor to pull and insert the sucker rod and pump before and after eachsteam cycle or hot fluid injection, which could be 2 to 4 times per yearper well, and downtime of the oil operation. Thus, periodic short cyclesteam injection or hot fluid injection will maintain consistent higheroil production.

Furthermore, it is to be appreciated that water may be recovered fromthe subterranean formation 132 after condensation of the high-qualitydownhole steam 166 and may then be re-circulated to the surface 136through the innermost tubing string 276, via the sucker rod and pump 270and/or the electrical submersible pump (ESP) 272, where it can betreated at the surface 136 for reuse, which has tremendous economicalbenefits such as savings in water cost and eliminate the costly off-sitedisposal of the produced water as well as the unknown timing andapproval of permitting and the drilling cost of an on-site waste waterinjection well. In other words, any liquid substance may be recoveredfrom the subterranean formation 132 after condensation of its vapor to aliquid. In practice, such recovery of the liquid substance may takeplace in the course of removal of the released deposits from thesubterranean formation.

Such fluid recovery is also beneficial especially when using the liquid142 as a heated feedwater which is injected down the innermost tubingstring 248 at a temperature of about 250° F., which due to the pressureand the lack of an exchange of heat from the hot heat transfer fluid 250being operated in such a fashion (low temperature, restricted or noflow, etc.), does not convert into a vapor phase, thereby allowing veryhot water or hot oil injection into the vertical wellbore 130 for anydesignated time period desired. A hot water or hot oil (fluid) injectionhas shown to successfully reduce the viscosity of the heavy viscous oil.A viscosity curve shows that when a heavy oil formation is heated toabout 160° F. viscosity reduction down to about 500 centipoise isachieved to sufficiently liquefy the deposits 134, such as heavy oil, toflow through the subterranean formation 132 to the vertical wellbore 130or to another nearby production well.

In the various embodiments disclosed herein, the vertical wellbore 130and the various tubing strings may be formed of insulated/uninsulatedconcentric coiled tubing string, insulated/uninsulated threaded tubingstring such as Macaroni threaded tubing, Vacuum Insulated Tubing orThermocase® insulated threaded tubing, which is commercially availablefrom Vallourec Tube-Alloy, or wireline tool. Coiled tubing string iswell known to those skilled in the art and refers generally to metalpiping that is spooled on a large reel. Macaroni threading tubing iswell known to those skilled in the art. Thermocase® insulated threadedtubing is well known to those skilled in the art. Coiled tubing,Thermocase® tubing and Macaroni threaded tubing may have a diameter ofabout 1 inch to about 5 inches. For example, with reference made to FIG.2A showing in cross-section the concentric tubing strings 220, theinnermost tubing string 276 may have a diameter of between 1 inch to 2inches in one embodiment, and in another embodiment has a 1⅞ inchdiameter. The innermost tubing string 248 may have a diameter of between1½ inch to 2⅞ inches in one embodiment, and in another embodiment has a1⅝ inch diameter. The outermost tubing string 252 may have a diameter ofbetween 2 inches to 6 inches in one embodiment, and in anotherembodiment has a 5 inch diameter. The casing/annulus 260 may have adiameter of between 5 inches to 9⅞ inches in one embodiment, and inanother embodiment has a 7 inch diameter. Of course, those skilled inthe art will understand that the various embodiments are not limited tocoiled tubing and threaded tubing, or to any particular dimensions ofthe tubing.

In some embodiments, an expandable tubular may be used in the verticalwellbore 130 as part of the concentric tubing strings 220. Expandabletubulars are described in, for example, U.S. Pat. No. 5,366,012 toLohbeck and U.S. Pat. No. 6,354,373 to Vercaemer et al., each of whichis incorporated by reference as if fully set forth herein.

The downhole heating configuration disclosed herein generatesconvective, conductive and/or radiant energy that heats both thefeedwater/steam generation string, i.e., (steam generation) innermosttubing string 248 and the casing/annulus 260. Accordingly, a layer ofinsulation (not shown) may be provided between the hot heat transferfluid inlet tubing string or outermost tubing string 252 and the returncooled heat transfer fluid outlet of the casing/annulus 260. A granularsolid fill material may also be placed between the casing/annulus 260and the subterranean formation 132. The casing/annulus 260 mayconductively heat the fill material, such as a gas, which in turnconductively heats the subterranean formation 132. The casing/annulus260 may include vacuum insulated tubing. A gas drive with the desiredpressure could be employed to effectively push the heat from thecasing/annulus 260 away from the vertical wellbore 130 and into thesubterranean formation 132.

Referring again to FIG. 1 and FIG. 2, the hot heat transfer fluid 250 isdelivered from the surface 136 to the outermost tubing string 252through a hot heat transfer fluid inlet conduit 180. The hot heattransfer fluid 250 is pumped and circulated downhole through the hotheat transfer fluid inlet conduit 180 via a pump 182. After exitingthrough the distal end 262 of the outermost tubing string 252, thecooled heat transfer fluid 250 ascends/is drawn or circulated back tothe surface 136 in the conduit spacing provided between tubing strings252, 260 or the casing/annulus to a hot heat transfer fluid outletconduit 184. The suction side of pump 182 draws on the hot heat transferfluid 250 heated in a surface thermal fluid heater 186, which causes thereturning cooled heat transfer fluid to be drawn into the heater 186 viaoutlet conduit 184. Also, the built up wellbore pressure will bring thereturning cooled heat transfer fluid to the surface. The returningcooled heat transfer fluid is then reheated by the thermal fluid heater186, e.g. from the combustion of fuel 188 from a fuel tank 190, anddelivered under pump pressure to the heat transfer fluid inlet conduit180 as the hot heat transfer fluid 250. Accordingly, together withoutermost tubing string 252, casing/annulus 260, the fluid inlet conduit180, fluid outlet conduit 184, the pump 182, and thermal fluid heater186 form a closed-loop heat transfer fluid system which provides acontinuously circulating hot heat transfer fluid in operation.

Although the pump 182 is depicted positioned on the hot side of thethermal fluid heater 186, in other embodiments it may be positioned onthe cool side thereof. Additionally, a reserve storage flask on thesurface containing additional heat transfer fluid 250 may be included inthe closed loop to ensure sufficient heat transfer fluid in thehigh-quality downhole steam generation section 110. It is to beappreciated that according to factors such as pump capability, thermalfluid heater capability, distance between surface 136 and the bottom ofthe vertical wellbore 130, and the type of heat transfer fluid 250, forexample, the tube sizing for the outermost tubing string 252,casing/annulus 260, the fluid inlet conduit 180, fluid outlet conduit184, as well as flow rate of the hot heat transfer fluid 250 within theclosed-loop system may vary as is needed to produce a desired steamquality within the high-quality downhole steam generation section 110that is delivered to the lower section 164 of the vertical wellbore 130Likewise, similar factors are applicable to the flow rate of the liquid142 into the innermost tubing string 248 provided by surface pump 140 aswell as tube sizing of the innermost tubing string 248. Determining suchfactors and choosing such equipment as pumps, thermal fluid heater,tubing types and sizes, location and type of feedback/control sensors,composition of the heat transfer fluid 250 and the liquid 142, toaddress such factors as well as determining the needed operatingparameters, such as temperatures, pressures, and flow rates in thearrangement 100, for example, to provide a desired steam qualitydownhole is well within the skill set of a person skilled in the relatedart. It is also to be appreciated that well operators can controlvarious steam injection parameters, such as: steam injection rate,injection pressure, injection temperature, and injection volume. Forexample, in any one of the herein disclosed embodiments, the steaminjection rate, injection pressure steam injection temperature, and theinjection volume might be controlled at the surface.

The thermal packer 156 may be provided with a feed valve(s) 292 whichcontrols the rate of the steam that is provided into the lower section164 of the vertical wellbore 130. In one embodiment, the feed valve(s)192 responds to the pressure differences between the steam generated inthe high-quality downhole steam generation section 110 and the vaporpressure within the lower section 164 of the vertical wellbore 130 sothat vapor quality is maintained at a high value.

The thermal fluid heater 186 is configured to operate on any of avariety of energy sources. For example, in one embodiment, the thermalfluid heater 186 operates using combustion of a fuel that may includenatural gas, propane, methanol, and biofuel. The thermal fluid heater186 can also operate on electricity and solar energy.

The heat transfer fluid 250 is heated by the thermal fluid heater 186 toa very high temperature. In this regard, the heat transfer fluid 250should have a very high boiling point. In one embodiment, the heattransfer fluid is molten sodium with a high boiling temperature ofapproximately 1,150° F. Thus, the thermal fluid heater 186 heats theheat transfer fluid to a temperature as high as 1,150° F. In still otherembodiments, the heat transfer fluid 250 may be diesel oil, gas oil, andsynthetic heat transfer fluids, e.g., Therminol™ heat transfer fluidwhich is commercially available from Solutia, Inc., Marlotherm™ heattransfer fluid which is commercially available from Condea Vista Co.,Syltherm™, Duratherm™, Paratherm™ and Dowtherm™ heat transfer fluidwhich is commercially available from The Dow Chemical Company or anysynthetic non corrosive heat transfer fluid, for example. Accordingly,in these other embodiments, the heat transfer fluid 250 which may be asynthetic, is heated to a temperature as high as of 950° F. or anotherlower temperature. In still other embodiments, the heat transfer fluid250 is heated to a temperature that is greater than 400° F. tocompensate for the thermodynamics of the conversion from liquid 142 tothe high-quality downhole steam 166.

In certain embodiments, a surfactant may be used to improve theeffectiveness of the heat transfer fluid. Surfactants are compounds thatlower the surface tension between a liquid and, for example, a solid(such as the tubing string walls). In this regard, a surfactant-baseddrag-reducing additive is injected in the concentric tubing string ofthe hot heat transfer fluid 250. The surfactant effectively reduces thepressure drop in the hot heat transfer fluid 250 and increases the flowrate of the hot heat transfer fluid 250.

Referring now to FIG. 3, a cross-sectional view of a second embodimentof a high-quality downhole steam generation and oil productionarrangement 300 in accordance with the present invention is illustrated.As the oil production arrangement 300 of FIG. 3 is similar to theembodiment illustrated in FIG. 1, only the differences are discussedhereafter.

FIG. 3 illustrates an embodiment in which emissions 302 from the thermalfluid heater 186 are introduced in the liquid 142. The emissions 302 arethen provided downhole through a conduit 146, past the thermal packer156, down into the vertical wellbore 130, and to the area of thesubterranean formation 132 to provide the oil production arrangement 300with zero emissions 302 at the surface of environmental unfriendlycompounds, such as carbon dioxide and nitric oxide that result from thecombustion of fuel 188 to heat the fluid 250. In this embodiment, theliquid 142 carries the emissions 302 within the innermost tubing string248, below the thermal packer 156 into the vertical wellbore 130 wheresuch emissions 302 are released into either a non-oil bearingsubterranean formation 132 where the emissions are sequestered, ordeposits 134 which may be affected by the emissions that helps reducethe viscosity of the oil. In the latter embodiment, for example, theaddition of emissions may effectively improve the properties of thedeposits 134 such as reducing the viscosity of heavy oil containedtherein.

The concentricity of the various tubing strings in the vertical wellbore130 in this oil production arrangement 300 is illustrated in thecross-sectional view of FIG. 3A and taken along section line 3A-3A inFIG. 3. As in the previous arrangement 100, the hot heat transfer fluid250 is carried downward through the outermost tubing string 252, and thecooled transfer fluid is returned upward in the conduit spacing providedbetween the casing/annulus 260 and the outermost tubing string 252 tothe thermal fluid heater 186 for reheating and recirculation. A layer ofinsulation (not shown) may be provided between the outermost tubingstring 252 and the casing/annulus 260 to prevent heat transfer from thehot heat transfer fluid 250 to the cooled transfer fluid being returnedto the surface for reheating. Liquid 142 is carried downward through theinnermost tubing string 248 which is converted into high-qualitydownhole steam 166 via an exchange of heat from the hot heat transferfluid 250 flowing in the outermost tubing string 252 in a similar manneras previously discussed above in reference to the arrangement depictedby FIG. 1. Likewise, as in the embodiment of FIG. 1, the recoveredhydrocarbons in the oil production arrangement 300 are delivered to thesurface via a sucker rod and pump 270 and/or an electrical submersiblepump (ESP) 272 extending within the vertical wellbore 130.

Referring now to FIG. 4, a cross-sectional view of a third embodiment ofa high-quality downhole steam generation and oil production arrangement400 in accordance with the present invention is illustrated fornon-thermally completed wells. As the oil production arrangement 400 ofFIG. 4 is similar to the embodiment illustrated in FIG. 1, only thedifferences are discussed hereafter.

FIG. 4 illustrates an embodiment in which high-quality downhole steamgeneration section 110 is defined between the wellhead 154 and a plate410 welded to the casing/annulus 260. In other words, the casing/annulus260 is internally sectioned by the plate 410 such that the high-qualitydownhole steam generation section 110 is defined above the plate 410,and the lower section 164 is defined as being below the plate 410,wherein the thermal packer 156 is provided in the lower section 164. Inthis manner, the thermal packer 156 can be provided as frangible thermalcups, such as disclosed by U.S. Pat. No. 4,385,664, the disclosure ofwhich incorporated fully herein by reference. The advantage of such anoil production arrangement 400 is that thermal packer 156 can move withthe expansion of the tubing as well as placed at a desired location inthe vertical wellbore 130 to reduce the size of the lower section 164,and to reduce heat loss from the lower section 164, as well as the heatdamage to a non-thermally completed casing/annulus 260 with non-thermalcement.

As shown by FIG. 4, a collar 420 is welded in the plate 410 to provide athrough bore such that the sucker rod and pump 270 and/or an electricalsubmersible pump (ESP) 272 can be extended below the thermal packer 156within the vertical wellbore 130. Threads or a shoe 430 are provided atthe top of the collar for threading to/seating the innermost tubingstring 248. A tail pipe 440, to which the thermal packer 156 surroundsbelow the plate 410, likewise is connected to the collar 420 such thatit is in fluid communications with the innermost tubing string 248. Asthe tail pipe 440 extends below the thermal packer 156, steam generatedin the high-quality downhole steam generation section 110 flows from theinnermost tubing string 248 and into the vertical wellbore 130 below thethermal packer 156. As the casing/annulus 260 is internally sealed bythe plate 410 and the innermost tubing string 248 when connected to thecollar 420, the hot heat transfer fluid 250 will continually circulatedthrough the outermost tubing string 252, and casing/annulus 260 abovethe plate 410 to convert the liquid 142 which flows in the innermosttubing string 248 into high-quality downhole steam 166 as discussedabove in reference to FIG. 1. In such a three string embodiment, it isto be appreciated that due to the spacing provided between the innermosttubing string 248 and the outermost tubing string 252, the volume of thehot heat transfer fluid 250 needed to be circulated in the oilproduction arrangement (system) 400 can be less than the volume thatwould be needed in embodiments that use the casing/annulus 260 to definepart of the return conduit for the hot heat transfer fluid 250. In stillother embodiments, plate 410 may be optional in which the outermosttubing string 252 extends to and is sealed at the bottom by the thermalpacker 156 in a similar manner as provided by plate 410 in thepreviously described embodiment.

The concentricity of the various tubing strings in the vertical wellbore130 in this oil production arrangement 400 is illustrated in thecross-sectional view of FIG. 4A and taken along section line 4A-4A inFIG. 4. Insulation 450 is provided adjacent the casing/annulus 260,which in this illustrated embodiment is a non-thermally completedcasing/annulus 260 with non-thermal cement. In this manner, the cooledtransfer fluid 250 returns upward in the conduit spacing providedbetween the insulation 450 and the outermost tubing string 252 to thethermal fluid heater 186 for reheating and recirculation.

Turning now to FIG. 5, a cross-sectional view of a fourth embodiment ofa high-quality downhole steam generation and oil production arrangement500 in accordance with the present invention is illustrated, which isreferred to steam drive or steam flooding. As the oil productionarrangement 500 of FIG. 5 is similar to the embodiment illustrated inFIG. 1, only the differences are discussed hereafter.

As noted above, in the embodiment of FIG. 1, the recovered hydrocarbonsare delivered to the surface via a sucker rod and pump 270 or anelectrical submersible pump (ESP) 272 extending within the verticalwellbore 130. In contrast, in the embodiment of FIG. 5, a recoveryarrangement includes a separate vertical oil production wellbore 510 anda horizontal oil collection wellbore 520. In this regard, high-qualitydownhole steam 166 generated in the high-quality downhole steamgeneration section 110 adds thermal energy to hydrocarbons from thesubterranean formation 132 in the lower section 164 of the verticalwellbore 130 and serves to reduce the viscosity of the hydrocarbons fromthe subterranean formation deposits 134, causing the hydrocarbons fromthe subterranean formation 132 to flow downward due to gravity drainage.The downward flowing hydrocarbons (e.g., via gravity drainage) arecollected in the horizontal oil collection wellbore 520. Thehydrocarbons are brought to the surface through the vertical section ofa horizontal oil collection wellbore 520, and are transported to one ormore tanks 174 (not shown) on the surface. In this regard, the suckerrod and pump 270 and/or the electrical submersible pump (ESP) 272 areprovided near the bottom of the vertical oil production wellbore 510.

It is to be appreciated that in such an embodiment, the innermost tubingstring 276 is optional, and has been left out in the illustratedembodiment, and as also depicted by FIG. 5A taken along section line5A-5A in FIG. 5. In one embodiment, the electrical submersible pump(ESP) 272 and all electrical cabling necessary for operation and controlof the pump (ESP) 272 are provided within the vertical oil productionwellbore 510. In the illustrated embodiment of FIG. 5, the vertical oilproduction wellbore 510 is separate from the vertical wellbore 130. Inother embodiments, the vertical section of a horizontal oil collectionwellbore 520 may be formed as a part of the vertical wellbore 130. Ofcourse, those skilled in the art will recognize that there may be one ormore horizontal oil collection wellbores 520 and one or more verticaloil production wellbores 510 for each vertical wellbore 130. Similarly,there may be a plurality of one or more vertical wellbores 130 for eachhorizontal oil collection wellbore 520 and/or each vertical section of ahorizontal oil collection wellbore 520 for improved high-qualitydownhole steam distribution. Moreover, as is depicted by FIGS. 6 and 6A,the vertical wellbore 130 likewise may connect to one or more horizontaland/or lateral wellbores 630 in which high-quality downhole steam 166 isinjected through the perforations 168 directly into such horizontalwellbores 630 for more efficient transfer of heat to the deposits 134.Accordingly, the high-quality downhole steam generation and injectionarrangements described in the above embodiments are suitable for use insteam-assisted gravity drainage (SAGD) recovery of hydrocarbons from asubterranean formation as is also depicted by FIG. 6.

Furthermore, as is depicted in FIGS. 7 and 7A, innermost tubing string248 in the vertical wellbore 130 may also connect to one or morehorizontal wellbores 630 by a perforated pipe or slotted liner 710 torelease the high-quality downhole steam 166 which is directed throughliner perforations 720, and directly into the subterranean formation 132around the horizontal wellbores 630. The introduction of the perforatedpipe or slotted liner 710 into the horizontal wellbores 630 provides formore efficient transfer of heat to the deposits 134, reducing the heatlosses through undirected heat transfer. This embodiment may lackperforations 168 in the casing/annulus 260, as they may not be needed ifthe heat is directed into the horizontal wellbores 630 through theperforated pipe or slotted liner 710. Additionally, as is depicted inFIGS. 8 and 8A, the high-quality downhole steam 166 may be sent throughinnermost tubing string 248 from the vertical wellbore 130 and into thesteam chambers 810 within one or more horizontal wellbores 630 where thehigh-quality downhole steam 166 is released through chamber perforations820 and directly into the subterranean formation 132. The introductionof the steam chambers 810 into the horizontal wellbores 630 provides fora more consistent injection of the high-quality downhole steam 166throughout the subterranean formation 132. This creates a more uniformtemperature profile across the subterranean formation 132, avoiding hotspots and cold spots that may otherwise occur. As depicted by FIG. 8Ataken along section line 8A-8A in FIG. 8, the steam chambers 810 arelocated concentrically within the innermost tubing string 248. Thehigh-quality downhole steam generation and injection arrangementsdescribed in the above embodiments are suitable for use insteam-assisted gravity drainage (SAGD) recovery of hydrocarbons from asubterranean formation as is also depicted by FIG. 7 and FIG. 8.

Moreover, as is depicted by FIGS. 9 and 9A, in arrangement 900 thevertical wellbore 130 likewise may connect to two or more horizontalwellbores 630 in which high-quality downhole steam 166 is injectedthrough the perforations 168 through perforated pipe or slotted liner710 and directly into such horizontal wellbores 630 for more efficienttransfer of heat to the deposits 134. Also as depicted in FIGS. 9 and9A, the vertical oil production wellbore 510 may connect to two or morehorizontal oil collection wellbores 520. This or similar embodiments mayalso include the use of steam chambers 810 and chamber perforations 820in the horizontal wellbores 630. Accordingly, the high-quality downholesteam generation and injection arrangements described in the aboveembodiments are suitable for use in steam-assisted gravity drainage(SAGD) recovery of hydrocarbons from a subterranean formation as is alsodepicted by FIG. 6.

In another embodiment, the one or more horizontal oil collectionwellbore 520 connected to the vertical oil production wellbore 510 mayinclude a flow control system to control unwanted fluids or steam aswell as return the wells back to desired performance levels. Such a flowcontrol system can be installed in the horizontal oil collectionwellbore 520 either before or after the well's completion. The flowcontrol system can be used to prevent or remedy negative effects causedby reservoir heterogeneities, breakthrough of undesired fluids,heel-to-toe effect, hot spots, and steam production. The installation ofa flow control system post-completion can remove the need to recompletethe well or drill a new well. The flow control system is comprised of aseries of flow control devices and high-temperature packers inside theexisting completion within tubing to equalize the inflow ofhydrocarbons. The high-temperature packers compartmentalize flow incertain areas of the well, helping channel production through the flowcontrol devices. One suitable example of such a flow control device thatcan be used in such a flow control system is the EQUALIZER retrofit (RF)flow control device from Baker Hughes (Houston, Tex.). The flow controlsystem can be installed as part of a pre-existing perforated liner orscreen completion, and improving hydrocarbon recovery overall. Uponbreakthrough of an undesired fluid such as water or steam, the pressuredrop across the device increases, causing the undesired fluid to bechoked back to avoid the breakthrough in the horizontal oil collectionwellbore 520. The pressure drop then decreases for desired fluids andhydrocarbons. Likewise, different flow resistant rating settings can beselected for each flow control device, enabling customized flow controloptions for each horizontal oil collection wellbore 520.

Turning now to FIG. 10, a cross-sectional view of a fifth embodiment ofa high-quality downhole steam generation and arrangement 1000 inaccordance with the present invention is illustrated, which is referredto as cyclic steam stimulation or huff-and-puff. As the arrangement 1000of FIG. 10 is similar to the embodiment illustrated in FIG. 1, only thedifferences are discussed hereafter.

Unlike the embodiment depicted by FIG. 2, the sucker rod and pump 270and/or the electrical submersible pump (ESP) 272 are not provided withinan innermost tubing string 276 in the arrangement 1000, as is bestdepicted by FIG. 10A. As such, separate steam lines/tubing arrangementshave to be removed from the vertical wellbore 130 before or after asteam cycle in order to install the sucker rod and pump 270 and/or theelectrical submersible pump (ESP) 272 along with a separate oilproduction outlet conduit 178 in order to recover the hydrocarbons fromthe vertical wellbore 130. In other words, the generation and providingof the high-quality downhole steam 166 in the vertical wellbore 130 aswell as the capturing and pumping of the hydrocarbons to the surface 136from the vertical wellbore 130 do not take place simultaneously. Duringthe oil production phase, the hot heat transfer fluid 250 continuallycirculates, allowing the oil production tubing to remain hot. Thisenables the viscous very heavy oil deposits 134, usually less than 10API gravity, to be easily pumped up without the need for chemicaltreatment to lower the viscosity. Accordingly, some of the notedadvantages of the simultaneous high-quality downhole steam generationand oil production arrangement shown by FIG. 2 may not be seen by thearrangement 1000 depicted by FIG. 10 as such an arrangement 1000 mayhave some of the costs associated with a production rig, and the laborto pull and insert the sucker rod and pump 270 and/or the electricalsubmersible pump (ESP) 272 before and after each steam cycle, whichcould be 2 to 4 times per year per well, as well as the downtime of theoil operation. Nonetheless, all of the other remaining noted advantagesdisclosed herein would still result from the arrangement 1000 depictedby FIG. 10.

The concentricity of the various tubing strings in the vertical wellbore130 in this arrangement 1000 is illustrated in the cross-sectional viewof FIG. 10A and taken along section line 10A-10A in FIG. 10. In theillustrated embodiment, the sucker rod and pump 270 and/or theelectrical submersible pump (ESP) 272 are shown along with the steamlines/tubing arrangements wherein a recirculating hot heat transferfluid 250 flows down into the vertical wellbore 130 via an outermosttubing string 252. Additionally, the liquid 142 injected into theinnermost tubing string 248 heated by a thermal fluid heater 186 isdepicted in the illustration. The sucker rod and pump 270 and/or theelectrical submersible pump (ESP) 272 are not provided within aninnermost tubing string 276 in the arrangement 1000, as an oilproduction outlet conduit 178 must be installed with the sucker rod andpump 270 and/or the electrical submersible pump (ESP) 272 in order torecover the hydrocarbons from the vertical wellbore 130.

Referring now to FIG. 11, a cross-sectional view of an embodiment of asimultaneous downhole hot fluid injection and oil production arrangement1100 in accordance with the present invention is illustrated. As thearrangement 1100 of FIG. 11 is similar to the embodiment illustrated inFIG. 2, only the differences are discussed hereafter.

FIG. 11 illustrates an embodiment in which the subterranean formation132 is heated with hot feedwater 1110 converted from the liquid 142, toflood the subterranean formation 132. The liquid 142 is injected downthe innermost tubing string 248 where the hot heat transfer fluid 250exchanges its heat energy to the liquid 142, raising the temperature toabout 250° F., or in some embodiments between about 400-1150° F.converting it to hot feedwater 1110. Due to a low pressure and decreasedexchange of heat from the hot heat transfer fluid 250 because of lowtemperature, restricted of no flow, etc., the liquid 142 does notconvert into vapor phase as would happen in certain other embodiments,thereby allowing very hot fluid (e.g., water or oil) injection into thevertical wellbore 130. The hot feedwater 1110 extends below a thermalpacker 156 positioned in the vertical wellbore 130, and directed throughperforations 168 provided in the casing/annulus 260 to achieve a hotwater injection (flood) in the subterranean formation. The hot fluidinjection of the subterranean formation 132 creates thermal stimulationand enhanced recovery. A hot fluid injection has also shown tosuccessfully reduce the viscosity of the heavy viscous oil to a degreethat the deposits 134 liquefy sufficiently to flow through thesubterranean formation 132 to the vertical wellbore 130 or to anothernearby production well.

The concentricity of the various tubing strings in the vertical wellbore130 in this arrangement 1100 is illustrated in the cross-sectional viewof FIG. 11A and taken along section line 11A-11A in FIG. 11. As in theprevious arrangement 100, the hot heat transfer fluid 250 is carrieddownward through the outermost tubing string 252, and the cooledtransfer fluid is returned upward in the conduit spacing providedbetween the casing/annulus 260 and the outermost tubing string 252 tothe thermal fluid heater 186 for reheating and recirculation. A layer ofinsulation 450 (not shown) may be provided between the outermost tubingstring 252, and casing/annulus 260 to prevent heat transfer from the hotheat transfer fluid 250 to the cooled transfer fluid being returned tothe surface for reheating. Here, liquid 142 is carried downward throughthe innermost tubing string 248 and converted to hot feedwater 1110, viaan exchange of heat from the hot heat transfer fluid 250 flowing in theoutermost tubing string 252 in a similar manner as previously discussedabove in reference to the arrangement depicted by FIG. 2, without theconversion to high-quality downhole steam 166. Likewise, as in theembodiment of FIG. 2, the recovered hydrocarbons in the oil productionarrangement 300 are delivered to the surface via a sucker rod and pump270 and/or an electrical submersible pump (ESP) 272 extending within thevertical wellbore 130. Moreover, as is depicted by FIGS. 12 and 12Awhich illustrate a hot fluid injection arrangement 1200, the thermalfluid heater 186, heat transfer fluid inlet conduit 180, and hot heattransfer fluid outlet conduit 184 may be replaced by connecting asurface heat exchanger 1210 directly to conduit 146, providing the hotfeedwater 1110 directly into the vertical wellbore 130. This embodimenteliminates the need for the outermost tubing string 252 and the hot heattransfer fluid 250 to exchange heat to the liquid 142, simplifying theprocess and the number of parts needed.

A detailed description of one or more embodiments of the disclosedapparatus and method are presented herein by way of exemplification andnot limitation with reference to the Figures.

Methane hydrate is a clathrate compound in which water molecules freezeabout methane molecules to form “cages” that trap the methane moleculestherein. Methane hydrate deposits are believed to represent significantpotential energy reserves for the energy industry but are difficult torecover. Due to the specific pressure and temperature requirements forthe formation of methane hydrate, these deposits are primarily formedunderground in subsea and arctic locations, frustrating their recovery.

A completion system for multilateral wellbores is envisioned. Thelateral wellbores include a first lateral wellbore and a second lateralwellbore. The lateral wellbores might be deviated and are provided byentirely separate lateral wellbores. It is noted, however, that therecan be a single parent lateral wellbore for the two proximately spacedlaterals with equal effect. These Figures are not provided in the patentapplication.

The laterals are formed at least partially in, through, or otherwiseproximate to a subsurface volume, which at least partially comprisesmethane hydrate. It is to be appreciated that the volume can include anynumber of other substances, e.g., sand, sediment, other gases, liquids,solids, etc. The volume might be located at a subsea or arctic location,or any other location satisfying the unique temperature and pressurerequirements that support the initial formation of methane hydrate as adeposit.

The first lateral wellbore is arranged to convey high-quality downholesteam into contact with the volume. The term “high-quality steam” meansa temperature greater than that of the methane hydrate, carrying energythat can be used to heat the volume. For example, flashing hot treatedfeedwater on the heat exchanger or high-quality downhole steamgeneration tube in the lateral wellbore produces high-quality downholesteam. A thermal fluid heater at the surface heats a heat transfer fluidthat descends downhole in a concentric tubing string. The hot heattransfer fluid exchanges the feedwater to a vapor or high-qualitydownhole steam emanating from the lateral wellbores perforationspermitting the high-quality downhole steam to be pumped into contactwith the volume.

The application of high-quality downhole steam to the volume will causeice in the volume to melt, thereby enabling methane to be liberated fromthe cage of previously frozen water molecules. By “liberated”, it ismeant that the methane is released from the methane hydrate in thevolume, that is no longer trapped, contained, or restricted by thefrozen water molecules of the methane hydrate, or otherwise is able tomove in order for the methane to be produced. The second lateralwellbore is accordingly arranged to receive the methane that isliberated from the methane hydrate in the volume. The second lateralwellbore can be provided with ports, perforations, or other openingswith or without screens in order to permit entry of the methane into thesecond lateral wellbore for production of the methane. In addition, insome embodiments, the second lateral wellbore will also include one ormore ESPs to assist in pumping the liberated fluid up-hole. Thecirculating hot heat transfer fluid in the concentric tubing string inthe lateral wellbore will provide sufficient amount of heat that willhelp reduce the chances of a hydrate plug forming up-hole of theformation.

In view of the above, it is to be appreciated that the functions ofsupplying heat from the hot heat transfer fluid and producing themethane are divided between the strings, with each of the stringshandling solely a designated task. In this way, the system can bearranged to more efficiently control the parameters relevant to theformation of methane hydrate, e.g., temperature and pressure.

Utilizing two separate lateral wellbores in the system enables the firstlateral wellbore to be located deeper than and/or or below the secondlateral wellbore with respect to gravity. This arrangement promotes theefficient production of methane in a variety of ways. For example, whilethe high-quality downhole steam will generally disperse in alldirections and form a pocket or envelop around the lateral wellbore, thepositioning of the first lateral wellbore deeper than the second lateralwellbore will enable the natural tendency of high-quality downhole steamto rise, i.e., travel opposite to the direction of gravity to primarilydirect the high-quality downhole steam from the lateral wellbore intothe volume. It will be understood that the second lateral wellbore couldbe otherwise located providing that the envelope of the high-qualitydownhole steam and hence liberated methane will have access to thelateral wellbore to promote production. The relatively low-densitymethane will tend to “rise above” water and other heavier molecules,causing the methane to move opposite to the direction of gravity andinto the lateral wellbore. It is also noted that sand, sediment, andother solid particles initially trapped in or with the volume orsurrounding ice will tend to move in the direction of gravity and settleabout the lateral wellbore hence being left behind instead of blockingthe progress of the methane into the lateral wellbore.

The lateral wellbore is arranged with an instrumentation line. Theinstrumentation line is included to assist in controlling operation ofthe system and can include fiber optic lines, hydraulic control lines,or power and/or data communication lines. The lines can include sensorstherewith or be otherwise configured to sense or monitor one or moreparameters, such as temperature and pressure, if fiber optic is used. Inthis way, the amount of high-quality downhole steam conveyed via thelateral wellbore can be tailored in response to changing downholeconditions. Also important is the condition within the lateral wellborethat can be controlled in order to prevent methane hydrate fromreforming and/or water molecules refreezing therein. For example, thehot heat transfer fluid provided in the concentric tubing string willkeep the volume and surrounding system components from freezing, but themethane and other fluids produced by the tubing string may coolsignificantly while traveling through the lateral wellbore to preventthe formation of methane hydrate or ice plugs within the lateralwellbore.

It is to be appreciated that the laterals represent one example ofsuitable lateral wellbore structures in which to install the first andsecond lateral wellbores. For example, the lateral wellbore structuresfor containing the first and second lateral wellbores are formed as oneor two separate lateral wellbores.

The system as described enables the method of producing methane frommethane hydrate enabling conveying high-quality downhole steam to aformation containing methane hydrate through a first lateral wellborelocated deeper than a second lateral wellbore section relative togravity; liberating methane from the methane hydrate; and receiving themethane in the second lateral wellbore section. But further, the systemlends itself to controlling any one or more parameters of methanehydrate stability, any one of which being capable of causing adestabilizing effect that results in the liberation of methane from thehydrate form.

In another embodiment, the high-quality downhole steam generation andinjection arrangements described in the above embodiments may be usedfor the purpose of downhole steam generation to remediate groundwatercontamination. In situ thermal remediation is the injection of energyinto the subsurface to mobilize and recover volatile and semi-volatileorganic contaminants. Steam-enhanced extraction is now commonly used toremediate contaminants from source zones. This and other embodiments ofthe present invention can be applied to a wide variety of contaminanttypes and in a wide variety of hydro-geologic conditions. When appliedaggressively, the downhole steam generator is capable of reducingresidual contamination to very low levels; the contamination is thendegraded by natural attenuation processes. The downhole steam generatorcan provide the heat to the subsurface that affects the physicalproperties of organic liquids in porous media that has a direct impacton reducing the levels of residual contamination that will remain afterthermal treatment. The use of this technology has obvious benefits forthe environments, as well as being more effective than other processesand methods.

In some embodiments where a recirculating hot heat transfer fluid 250transfers thermal energy a liquid 142, the hot heat transfer fluid 250used may be thermal oil. Traditionally, steam has been used for thisprocess due to its availability, low cost of water, and fewenvironmental issues. Thermal oils are heat transfer fluids thattransfer the heat from one hot source to another process. This could befrom a combustion chamber or from any exothermic process. The mainapplication is in fluid phase heat transfer. Thermal oils are availablein chemically different forms, but not limited to; synthetic oil, whichare aromatic compounds, petroleum based oils, which are paraffin's, andsynthetic glycol based fluids. Thermal oils are available in a widerange of specifications to suit the needs of various processes.

Currently available thermal oils have a maximum temperature limit ofabout 400° C. Effective heat transfer by steam uses latent heat, wherethe saturation pressure dictates the temperature at which heat transfertakes place. To achieve 350° C. of the steam, a pressure of 180 bar isrequired. To obtain a higher temperature, the pressure must beincreased. This in turn requires higher thickness for the heat exchangertubes, increasing the weight and thermal stresses, and requiring specialmanufacturing techniques. In contrast, even at 350° C., the pressurerequirements of thermal oils are just sufficient to overcome the systempressure drops, also decreasing the pumping costs. The system to supportthe use of thermal oil is also simple, requiring only a pump, expansionand storage tank, and the heat exchangers. A conventional surface steamboiler requires demineralized makeup water supply, drains, traps, safetyvalves, chemical additions, and blow downs. Using thermal oil over steamalso eliminates corrosion, scaling, fouling, tubing failure in the steamvessel and deposits in the heat transfer areas. Some examples of thermaloils that may be suitable for various methods and systems for recoveringpetroleum resources include, but are not limited to, Therminol fromSolutia Inc., Dowtherm from Dow Chemical Co., Exceltherm from RadcoIndustries Inc. and Paratherm from Paratherm Corp. While the maximumtemperature at which the thermal oil is thermally stable is the mostimportant characteristic, other characteristics to consider whendetermining which type or brand to use are the heat transferco-efficient, pumpability, serviceability, environmental issues such astoxicity, shipping restrictions and disposal methods, and oxidation anddegradation potential.

In some examples, the high-quality downhole steam generation andinjection arrangements described in the above embodiments may be used inconjunction with fracking methods of oil production. For example,high-quality downhole steam generation may be used to allow injection ofhigh-pressure, high-quality downhole steam to facilitate fracking ofsubterranean formations. The injection of high-pressure, high-qualitydownhole steam may result in the propagation of fractures in theformation or the rock layer. Steam fracking is a technique used tofracture the rock layer directly adjacent to the oil and gas well tosubstantially enhance hydrocarbon recovery. Steam fracking eliminatespotential environmental impacts, including contamination of groundwater, risks to air quality, the migration of gases and hydraulicfracturing chemicals to the ground water, the surface, surfacecontamination from spills and the health effects of these. Steamfracking points to the vast amount of low-volume produced viscous heavyoil, low-permeability diatomite, shale oil, tight oil, shale gas andcoal bed methane. Steam fracking is environmentally safe and willsatisfy the environmentalists and does not jeopardize the health ofinhabitants.

The foregoing description of embodiments has been presented for purposesof illustration and description. The foregoing description is notintended to be exhaustive or to limit embodiments of the presentinvention to the precise form disclosed, and modifications andvariations are possible in light of the above teachings or may beacquired from practice of various embodiments. The embodiments discussedherein were chosen and described in order to explain the principles andthe nature of various embodiments and its practical application toenable one skilled in the art to utilize the present invention invarious embodiments and with various modifications as are suited to theparticular use contemplated. As such, in further embodiments, featuresfrom specific embodiments may be combined with features from otherembodiments. For example, features from one embodiment may be combinedwith features from any of the other embodiments. For example, the threestring embodiment depicted by FIG. 4 may be suitable employed in any ofthe embodiments which use the casing/annulus 260 to define part of thereturn conduit for the hot heat transfer fluid 250 to reduce the numberof gallons of the hot heat transfer fluid needing to be circulated bythe system.

1. A system for producing hydrocarbons from a subterranean formationbelow a surface via a wellbore extending from the surface to thesubterranean formation, said system comprising: concentric tubingstrings positioned in the wellbore; a thermal packer positioned in thewellbore; a hot heat transfer fluid circulation system coupled to theoutermost tubing string and the casing/annulus for the return cooledheat transfer fluid to return to the surface to be reheated in thethermal fluid heater and recirculate down hole; a liquid supply isconfigured to provide a liquid or hot feedwater through a hot permanentinnermost tubing string of the concentric tubing strings that is insideand concentric to the outermost tubing string and the casing/annulus;and a thermal fluid heater configured to heat a heat transfer fluidcontinually circulated through the outermost tubing string above thethermal packer positioned in the wellbore to immediately converts theliquid or hot feedwater, which descends in the innermost tubing string,into high-quality downhole steam, wherein the permanent innermost tubingstring extends below the surface such that the liquid or hot feedwaterimmediately converts to high-quality downhole steam inside the innermosthot tubing string that minimizes heat loss and is injected into thesteam injection wellbore below the thermal packer to heat thesubterranean formation to temperatures that allow for viscoushydrocarbon production from the subterranean formation.
 2. The system ofclaim 1, further comprising: at least one of an electrical submersiblepump (ESP) or a sucker rod and pump is configured to recover liquefiedhydrocarbons positioned near the bottom of the vertical wellbore abovethe perforations.
 3. The system of claim 2, further comprising: anotherpermanent tubing string that is an innermost tubing string of theconcentric tubing strings, wherein at least an electrical submersiblepump (ESP) or a sucker rod and pump is permanently provided in theinnermost tubing string allowing subsequent steam cycles and hydrocarbonproduction without removing the ESP or sucker rod and pump.
 4. Thesystem of claim 1, wherein the wellbore is connected to one or morehorizontal wellbores configured to inject high-quality downhole steaminto the horizontal wellbores.
 5. The system of claim 4, wherein theinnermost tubing string in the wellbore connects to one or morehorizontal wellbores by a perforated pipe or slotted liner to releasethe high-quality downhole steam through the liner perforations or bysteam chambers to release the high-quality downhole steam through thechamber perforations and directly into the subterranean formation aroundthe horizontal wellbores.
 6. The system of claim 1, further comprising:one or more horizontal wellbores configured to collect liquefiedhydrocarbons that can collect the hydrocarbons through gravity drainage;a vertical wellbore connected to one or more horizontal wellbores; and aproduction line in the vertical wellbore, which is configured to producethe liquefied hydrocarbons from one or more horizontal wellbores to thesurface.
 7. The system of claim 6, wherein an electrical submersiblepump (ESP) or a sucker rod extends to the surface within the verticalwellbore.
 8. The system of claim 6, further comprising: one or morewellbore systems wherein one or more horizontal wellbores configured tocollect methane from methane hydrate deposits are positioned above oneor more horizontal wellbores configured to inject high-quality downholesteam into the subterranean formation, wherein the methane released fromthe methane hydrate will rise up into the horizontal wellboresconfigured to collect methane.
 9. The system of claim 6, furthercomprising: a flow control system within the one or more horizontalwellbores; wherein; the flow control system comprises a series of flowcontrol devices and high temperature packers.
 10. The system of claim 1,wherein the hot heat transfer fluid comprises one or more of thefollowing: thermal oil, diesel oil, gas oil, molten sodium, and asynthetic non-toxic heat transfer fluid.
 11. The system of claim 1,further comprising: the introduction of emissions from the thermal fluidheater into the liquid or hot feedwater and then injecting the emissionswith the liquid or hot feedwater into the subterranean formation. 12.The system of claim 1, wherein one of the outermost tubing strings is acasing and/or annulus, and system further comprising a plate with acollar provided therein welded to the casing/annulus, and saidcasing/annulus being sectioned by the plate allowing a steam generationtubing defined above the plate, and the steam generation tubing extendsbelow the plate, wherein the thermal packer is provided in the lowersection of the casing/annulus and the hot heat transfer fluidcontinually circulated through the outermost tubing string and thecasing/annulus above the plate to convert the liquid or hot feedwater,which descends down hole in the hot innermost tubing string convertinginto high-quality downhole steam.
 13. A method of heating a subterraneanformation comprising: positioning concentric tubing strings in awellbore; heating a hot heat transfer fluid using a surface thermalfluid heater; flowing a liquid or hot feedwater downward through hotinnermost tubing string of the concentric tubing strings that is insideand concentric to the outermost tubing string and the casing/annulus,which does not convert to a vapor phase for a time period and whichextends below a thermal packer positioned in the wellbore to achieve ahot fluid injection in the subterranean formation; continuallycirculating the hot heat transfer fluid through the outermost tubingstring and the casing/annulus above the thermal packer such that theliquid or hot feedwater flowing through the very hot innermost tubingstring after the time period is converted into high-quality downholesteam, which is injected into the wellbore below the thermal packer andout of the perforations to heat the subterranean formation totemperatures that allow for hydrocarbon production from the subterraneanformation.
 14. The method of claim 13, further comprising: recoveringliquefied hydrocarbon deposits in a horizontal wellbore that can collectthe hydrocarbon through gravity drainage; and producing the liquefiedhydrocarbon deposits to the surface through a vertical production linethat is connected to and part of the horizontal wellbore.
 15. The methodof claim 13, further comprising: recovering liquefied hydrocarbons usingan electrical submersible pump (ESP) or sucker rod and a pump at thebottom of the vertical wellbore.
 16. The method of claim 15, wherein theelectrical submersible pump (ESP) or sucker rod and pump extends throughan innermost tubing string of the concentric tubing strings.
 17. Themethod of claim 13, wherein the liquid or hot feedwater is either wateror oil, and the hot heat transfer fluid is heated between 400-1150° F.18. The method of claim 17, wherein the hot heat transfer fluid isheated by a heat exchanger.
 19. The method of claim 13, wherein the hotheat transfer fluid continually circulates during the oil productionphase allowing the oil production tubing to remain very hot enabling theviscous very heavy oil, typically less than 10 API gravity oil, to beeasily pumped up the wellbore to the surface without the need for achemical treatment to lower the viscosity of the heavy oil.
 20. A systemfor remediating groundwater contamination in a subterranean formationbelow a surface via a wellbore extending from the surface to thesubterranean formation, said system comprising: concentric tubingstrings positioned in the wellbore; a thermal packer positioned in thewellbore; a hot heat transfer fluid circulation system coupled to theoutermost tubing string and the casing and/or annulus for the returncooled heat transfer fluid to return to the surface to be reheated inthe thermal fluid heater and recirculate down hole; a liquid supplyconfigured to provide a liquid through a hot permanent innermost tubingstring of the concentric tubing strings that is inside and concentric tothe outermost tubing string and the casing/annulus; and a thermal fluidheater configured to heat a heat transfer fluid continually circulatedthrough the outermost tubing string and casing/annulus above the thermalpacker positioned in the wellbore to immediately converts the liquid,which descends in the innermost tubing string, into high-qualitydownhole steam, wherein the permanent innermost tubing string extendsbelow the surface such that the liquid immediately converts tohigh-quality downhole steam inside the innermost hot tubing string thatminimizes heat loss and is injected into the steam injection wellborebelow the thermal packer to heat the subterranean formation totemperatures that allow for recovery of volatile and semi-volatileorganic contaminants from the subterranean formation or degradation bynatural attenuation processes.